The control of fluid produced from each hydrocarbon reservoir zone can significantly improve the recovery factor. It can also minimize the production of undesirable fluids such as water and gas. In addition, such control could assist reservoir engineers with flood injections and chemical agent treatment.
Phase transitions play an important role in the producibility of oil or gas wells and their associated reservoirs. Fluid produced from an oil well will typically have a number of hydrocarbon components and, while these may coexist as liquid at the temperature and pressure of the reservoir rock, the lighter components may begin to evolve as gas as the wellbore and formation pressure is reduced. Such evolution of gas in the reservoir rock can seriously decrease the oil phase relative permeability and, ultimately, the fraction of oil that may be recovered. Knowledge of the bubble point is also useful in determining the composition of the hydrocarbon mixture in the reservoir. Similarly, in gas wells, heavier components may begin to condense as a liquid as gas is produced. Liquid in the pore spaces of a gas well will similarly reduce the permeability to gas. It is important to maintain either pure liquid or pure gaseous phase in the reservoir, depending on the type of well.
Reservoir performance calculations greatly benefit from a knowledge of the location of the fluid (p, T, x) pressure-temperature-composition phase transitions. At either reservoir or producing zone conditions the most significant phase borders are the formation of a liquid from a gas (dew point) and a gas from a liquid (bubble point). The phase behavior of black oils is usually dominated by the mole fraction of low molecular mass components, while for retrograde condensates the phase behavior is determined by mole fraction of high molecular mass components.
Fluid phase behavior also plays an important role in production engineering both down hole and at surface. It is often desirable to produce with the “drawdown”, or decrease in wellbore pressure relative to the formation pressure, as large as possible to give the greatest production rate. Drawdown is limited, however, by the need to avoid phase changes in the fluid. In addition, failure to maintain a single phase in a horizontal well can create gas pockets that inhibit flow in production tubing. Both Reservoir and Production Engineers require the hydrocarbon phase be maintained homogeneous to optimize production while minimizing risk of reservoir damage.
Conventionally, there are several methods by which the phase behavior of reservoir fluids can be determined. However, none of these methods lend itself to real-time down-hole sensors for in situ production control. Empirical correlations on laboratory data have been used to estimate phase borders. Alternatively, a bubble point can be estimated from a compositional analysis of fluid samples with an equation of state. Typically, samples collected down-hole and brought to the surface are liable to undergo both reversible and irreversible changes such as wax and asphaltene separation, that arise from temperature and pressure changes. In addition, the imperfect fluid transfer between sample apparatus and measuring apparatus alters the composition. Fluid thermophysical property analyses can be obtained at the well head, so reducing the time between sample collection and analysis. However, these approaches all require the handling and perhaps transportation of hazardous fluids. Finally, some properties of well fluids have been determined with a commercially available wireline tool down-hole, without removing the sample from the well. Commercial tools that can be used for this purpose are the Schlumberger Modular Formation Dynamics Tester (MDT) and the Western-Atlas Reservoir Characterization Instrument (RCI). Although in theory such devices could be used to provide, for a limited time period, real time in situ fluid properties, the sensors and methods are not sufficiently reliable for permanent or even semi-permanent operation.
None of the methods described above are performed on a routine basis and certainly never sufficiently often or rapidly to provide real-time data for process control. The only viable solution is permanent or semi-permanent down-hole monitoring.